Method for measuring transient electromagnetic components to perform deep geosteering while drilling

ABSTRACT

A transverse induction transmitter on an instrument induces currents in an earth formation when it is pulsed. Transient measurements made at transverse and axial receivers are used for determination of a distance to a bed boundary. This may be used to control the drilling direction. Alternatively, a transmitter on an instrument having a conductive body induces currents in the earth formation. Transient signals are measured and the effect of the conductive body is removed by using a reference signal measured in a homogenous space.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention is related to the field of transientelectromagnetic field measurements made in a geological formation.Specifically, the invention increases an azimuthal sensitivity andresolution of the transient field to formation boundaries.

2. Description of the Related Art

Electromagnetic induction resistivity instruments can be used todetermine the electrical conductivity of earth formations surrounding awellbore. An electromagnetic induction well logging instrument isdescribed, for example, in U.S. Pat. No. 5,452,761, to Beard et al. Theinstrument described in the Beard patent includes a transmitter coil anda plurality of receiver coils positioned at axially spaced apartlocations along the instrument housing. An alternating current is passedthrough the transmitter coil. Voltages which are induced in the receivercoils as a result of alternating magnetic fields induced in the earthformations are then measured. The magnitude of certain phase componentsof the induced receiver voltages are related to the conductivity of themedia surrounding the instrument.

The development of deep-looking electromagnetic tools has a longhistory. Such tools are used to achieve a variety of differentobjectives. Deep looking tools attempt to measure the reservoirproperties between wells at distances ranging from tens to hundreds ofmeters (ultra-deep scale). There are single-well and cross-wellapproaches, most of which are rooted in the technologies ofradar/seismic wave propagation physics. This group of tools is naturallylimited by, among other things, their applicability to only highresistivity formations and the power available down-hole.

At the ultra-deep scale, technology may be employed based on transientfield behavior. The transient electromagnetic (TEM) field method iswidely used in surface geophysics. Examples of transient technology areseen, for example, in Kaufman et al., 1983, “Frequency and transientsoundings”, Elsevier Science; Sidorov et al., 1969, “Geophysical surveyswith near zone transient EM.” published by NVIGG, Saratov, Russia; andRabinovich et al., 1981, “Formation of an immersed vertical magneticdipole field”: J. Geologiya I Geofizika, N 3. Typically, voltage orcurrent pulses that are excited in a transmitter initiate thepropagation of an electromagnetic signal in the earth formation.Electric currents diffuse outwards from the transmitter into thesurrounding formation. At different times, information arrives at themeasurement sensor from different investigation depths. Particularly, ata sufficiently late time, the transient electromagnetic field issensitive only to remote formation zones and does not depend on theresistivity distribution in the vicinity of the transmitter (see Kaufmanet al., 1983). This transient field is especially important for logging.Use of a symmetric logging tool using transient field measurements forformation detection is discussed, for example, in U.S. Pat. No.5,530,359, to Habashy et al.

U.S. Pat. No. 5,955,884, to Payton et al., discusses methods formeasuring transient electromagnetic fields in rock formations.Electromagnetic energy is applied to the formation and waveforms thatmaximize the radial depth of penetration of the magnetic and electricenergy. Payton comprises at least one electromagnetic transmitter and atleast one electric transmitter for applying electric energy. Thetransmitter may be either a single-axis or multi-axis electromagneticand/or electric transmitter. In one embodiment the TEM transmitters andTEM receivers are separate modules that are spaced apart andinterconnected by lengths of cable, with the TEM transmitter and TEMreceiver modules being separated by an interval of from one meter up to200 meters, as selected. Radial depth of investigation is related to theskin depth δ={square root}{square root over (2/σμω)} which in turn isrelated to frequency. Lower frequency signals can increase the skindepth. Similarly, the conductivity of the surrounding material inverselyaffects the skin depth. As conductivity increases, the depth ofinvestigation decreases. Finite conductivity casing of the apparatustherefore can reduce the depth of investigation.

Rapidly emerging measurement-while-drilling (MWD) technology introducesa new, meso-deep (3-10 meters) scale for an electromagnetic loggingapplication related to well navigation in thick reservoirs. A majorproblem associated with the MWD environment is the introduction of ametal drill pipe close to the area being measured. This pipe produces avery strong response and significantly reduces the sensitivity of themeasured EM field to the effects of formation resistivities and remoteboundaries. Previous solutions for this problem typically comprisecreating a large spacing (up to 20 meters) between transmitter andreceiver. Such a system is discussed in U.S. Pat. No. 6,188,222 B1, toSeydoux et al. The sensitivity of such a tool to remote boundaries islow. Currently, Stolar Horizon, Inc. is developing drill string radar(DSR) for Coal Bed Methane wells. DSR provides 3-D imaging within aclose range of the wellbore.

Currently, induction tools operate to obtain measurements either in thepresence of a primary field or by using transient field techniques.Examples of current techniques for obtaining measurements using eitherprimary field or transient field phenomena in measurement-while-drillingmethods include the Multiple Propagation Resistivity (MPR) device, andthe High-Definition Induction Logging (HDIL) device for open hole thatutilizes a transient technique. In these techniques, one or moretransmitters disposed along a drill tool act as a primary source ofinduction, and signals are received from the formation at receiver coilsplaced at an axial distance from the transmitters along the drill tool.One disadvantage of both MPR and HDIL methods is that the primary sourceof induction from the transmitter is always present during the timeframe in which the receivers are obtaining measurements from theformation, thereby distorting the intended signal. This can be solved byusing pulse excitations such as is done in a transient induction tool.

In a typical transient induction tool, current in the transmitter coildrops from its initial value I₀ to 0 at the moment t=0. Subsequentmeasurements are taken while the rotating tool is moving along theborehole trajectory. The currents induced in the drilling pipe and inthe formation (i.e. eddy currents) begin diffusing from the region closeto the transmitter coil in all the directions surrounding thetransmitter. These currents induce electromagnetic field componentswhich can be measured by induction coils placed along the conductivepipe. Signal contributions due to the eddy currents in the pipe areconsidered to be parasitic, since the signal due to these currents ismuch stronger than the signal from the formation. In order to receive asignal which is substantially unaffected by the eddy currents in thepipe, one can measure the signal at the very late stage, at a time inwhich the signals from the formation dominate parasitic signals due tothe pipe. Although the formation signal dominates at the late stage, itis also very small, and reliable measurement can be difficult. In priormethods, increasing the distance between transmitter and receiversreduces the influence of the pipe and shifts dominant contribution ofthe formation to the earlier time range. Besides having limitedresolution with respect to an oil/water boundary, such a system is verylong (up to 10-15 m) which is not desirable and convenient for an MWDtool.

A number of publications describe different applications of a MPRresistivity logging measurements (see, for example, Meyer, W., 1997,Multi-parameter propagation resistivity interpretation, 38^(th) SPWLAannual transactions, paper GG). All these publications describe dualpairs of transmitting antennas that permit long- and short-spacedmeasurements of phase difference and attenuation resistivities at thefrequencies of 2 MHz and 400 MHz. The resulting resistivity curvessupport detailed quantitative and petrophysical analysis. Currently, theMPR tool has no means to resolve formation in azimuthal direction andthe depth of investigation is limited to several feet.

MPR offers the benefits of several feet depth of investigation for R_(t)determination and bed boundary detection during reservoir navigationalong with the enhanced accuracy over a broad range of resistivities.The lack of resolving capability in the azimuthal direction andinability to resolve ultra-deep formation represent the main limitationof MPR for geosteering. Indeed, in a formation such as FIG. 3A, the MPRtool has the same readings as there would be in the formation in FIG.1B. Even a transversal arrangement of the transmitting and receivingcoils such as in 3DEX does not distinguish between the model in FIG. 3Aand the model in FIG. 3B.

U.S. patent application Ser. No. 10/295,969 of Tabarovsky discusses amethod of obtaining a parameter of interest, such as resistivity, of anearth formation using a tool having a body with finite, non-zeroconductivity. The method obtains a signal from the earth formation thatis substantially independent of the conductivity of the tool. A firstsignal is produced using a transmitter on the tool. An axially separatedreceiver receives a second signal that results from an interaction ofthe first signal with the earth formation. The second signal isdependent on the conductivity of the induction tool. This second signalcan be represented using a Taylor series expansion in one half of oddinteger powers of time. At least one leading term of the Taylor seriesexpansion can be subtracted from the second signal. By suitableprocessing of the signals, Tabarovsky teaches the determination of theformation resistivity. The examples given in the Tabarovsky applicationuse z-oriented transmitter and receiver coils.

There is a need for increasing a sensitivity and resolution of measuredtransient fields in to a distant boundary in a geologic formation. Thepresent invention fulfills this need.

SUMMARY OF THE INVENTION

One embodiment of the present is an apparatus and method of using anelectromagnetic instrument in a borehole in an earth formation. Currentthrough a transmitter is changed, thereby inducing currents in saidearth formation. The transmitter has an axial direction that may beinclined to the axis of the instrument. Temporal signals are received ateach of at least two receivers. One of the at least two receivers has anaxial direction that is substantially parallel to the axial direction ofthe transmitter, and another of the at least two receivers has an axialdirection inclined to said first axial direction. The changing of thecurrent may be either a switching on or a switching off. At least oneadditional transmitter may be provided on the instrument, the additionaltransmitter having an axis inclined to the axis of the firsttransmitter. Additional temporal signals are received at the at leasttwo receivers in response to a change in the current in the additionaltransmitter and these additional measurements may be further used todetermine a distance to the interface. The instrument may be part of abottomhole assembly (BHA) that includes a drillbit.

The determination of the distance may be done by a downhole processor othe BHA. The downhole processor may be further used to control thedrilling direction of the BHA. This may be used to control the drillingdepth and maintain the BHA at a desired distance from the interface thatmay be a bed boundary or a fluid interface (such as a gas-oil interface,an oil-water interface, or a gas-water interface).

In another embodiment of the invention, the determination of distance toan interface is done by subtracting a reference signal from a measuredtemporal signal. The reference signal may be obtained by making temporalmeasurements with the instrument in a substantially homogenous space.The transmitter axis may be parallel or perpendicular to the instrumentaxis. The instrument may include a conductive pipe and a non-conductingmaterial, possibly a ferrite separating the conductive pipe from thetransmitter.

BRIEF DESCRIPTION OF THE DRAWINGS

The present invention is best understood with reference to theaccompanying drawings in which like numerals refer to like elements andin which:

FIG. 1 (Prior Art) shows a measurement-while-drilling tool suitable foruse with the present invention;

FIG. 2 shows the measurement tool in a horizontal well;

FIGS. 3A-B show a transmitter-receiver system in relation to anformation boundary layer;

FIGS. 4A-B show modeling results representing transient responses for Zand X oriented receivers at a distance of 0.2 m from an X-orientedtransmitter;

FIGS. 5A-B show modeling results representing transient responses for Zand X oriented receivers at a distance of 2 m from an X-orientedtransmitter;

FIGS. 6A-B show modeling results representing transient responses for Zand X oriented receivers at a distance of 6 m from an X-orientedtransmitter;

FIGS. 7A-B show modeling results representing transient responses for Zand X oriented receivers at a distance of 12 m from an X-orientedtransmitter;

FIG. 8 shows a measurement tool in a horizontal well;

FIG. 9 shows a cross-section of the drill tool of FIG. 8;

FIGS. 10-12 shows original and improved signals from subtracting acalibration signal; and

FIGS. 13-15 shows original and improved signals from subtracting acalibration signal from an increased length of a ferrite section.

DETAILED DESCRIPTION OF THE INVENTION

FIG. 1 shows a schematic diagram of a drilling system 10 with adrillstring 20 carrying a drilling assembly 90 (also referred to as thebottom hole assembly, or “BHA”) conveyed in a “wellbore” or “borehole”26 for drilling the wellbore. The drilling system 10 includes aconventional derrick 11 erected on a floor 12 which supports a rotarytable 14 that is rotated by a prime mover such as an electric motor (notshown) at a desired rotational speed. The drillstring 20 includes atubing such as a drill pipe 22 or a coiled-tubing extending downwardfrom the surface into the borehole 26. The drillstring 20 is pushed intothe wellbore 26 when a drill pipe 22 is used as the tubing. Forcoiled-tubing applications, a tubing injector, such as an injector (notshown), however, is used to move the tubing from a source thereof, suchas a reel (not shown), to the wellbore 26. The drill bit 50 attached tothe end of the drillstring breaks up the geological formations when itis rotated to drill the borehole 26. If a drill pipe 22 is used, thedrillstring 20 is coupled to a drawworks 30 via a Kelly joint 21, swivel28, and line 29 through a pulley 23. During drilling operations, thedrawworks 30 is operated to control the weight on bit, which is animportant parameter that affects the rate of penetration. The operationof the drawworks is well known in the art and is thus not described indetail herein.

During drilling operations, a suitable drilling fluid 31 from a mud pit(source) 32 is circulated under pressure through a channel in thedrillstring 20 by a mud pump 34. The drilling fluid passes from the mudpump 34 into the drillstring 20 via a desurger (not shown), fluid line28 and Kelly joint 21. The drilling fluid 31 is discharged at theborehole bottom 51 through an opening in the drill bit 50. The drillingfluid 31 circulates uphole through the annular space 27 between thedrillstring 20 and the borehole 26 and returns to the mud pit 32 via areturn line 35. The drilling fluid acts to lubricate the drill bit 50and to carry borehole cutting or chips away from the drill bit 50. Asensor S₁ preferably placed in the line 38 provides information aboutthe fluid flow rate. A surface torque sensor S₂ and a sensor S₃associated with the drillstring 20 respectively provide informationabout the torque and rotational speed of the drillstring. Additionally,a sensor (not shown) associated with line 29 is used to provide the hookload of the drillstring 20.

In one embodiment of the invention, the drill bit 50 is rotated by onlyrotating the drill pipe 22. In another embodiment of the invention, adownhole motor 55 (mud motor) is disposed in the drilling assembly 90 torotate the drill bit 50 and the drill pipe 22 is rotated usually tosupplement the rotational power, if required, and to effect changes inthe drilling direction.

In the embodiment of FIG. 1, the mud motor 55 is coupled to the drillbit 50 via a drive shaft (not shown) disposed in a bearing assembly 57.The mud motor rotates the drill bit 50 when the drilling fluid 31 passesthrough the mud motor 55 under pressure. The bearing assembly 57supports the radial and axial forces of the drill bit. A stabilizer 58coupled to the bearing assembly 57 acts as a centralizer for thelowermost portion of the mud motor assembly.

In one embodiment of the invention, a drilling sensor module 59 isplaced near the drill bit 50. The drilling sensor module containssensors, circuitry and processing software and algorithms relating tothe dynamic drilling parameters. Such parameters preferably include bitbounce, stick-slip of the drilling assembly, backward rotation, torque,shocks, borehole and annulus pressure, acceleration measurements andother measurements of the drill bit condition. A suitable telemetry orcommunication sub 72 using, for example, two-way telemetry, is alsoprovided as illustrated in the drilling assembly 90. The drilling sensormodule processes the sensor information and transmits it to the surfacecontrol unit 40 via the telemetry system 72.

The communication sub 72, a power unit 78 and an MWD tool 79 are allconnected in tandem with the drillstring 20. Flex subs, for example, areused in connecting the MWD tool 79 in the drilling assembly 90. Suchsubs and tools form the bottom hole drilling assembly 90 between thedrillstring 20 and the drill bit 50. The drilling assembly 90 makesvarious measurements including the pulsed nuclear magnetic resonancemeasurements while the borehole 26 is being drilled. The communicationsub 72 obtains the signals and measurements and transfers the signals,using two-way telemetry, for example, to be processed on the surface.Alternatively, the signals can be processed using a downhole processorin the drilling assembly 90.

The surface control unit or processor 40 also receives signals fromother downhole sensors and devices and signals from sensors S₁-S₃ andother sensors used in the system 10 and processes such signals accordingto programmed instructions provided to the surface control unit 40. Thesurface control unit 40 displays desired drilling parameters and otherinformation on a display/monitor 42 utilized by an operator to controlthe drilling operations. The surface control unit 40 preferably includesa computer or a microprocessor-based processing system, memory forstoring programs or models and data, a recorder for recording data, andother peripherals. The control unit 40 is preferably adapted to activatealarms 44 when certain unsafe or undesirable operating conditions occur.

FIG. 2 shows an apparatus of the present invention. A transmitter coil201 and a receiver coil assembly are positioned along a damping portion200 of drill pipe for suppressing an eddy current. The longitudinal axisof the drill tool defines a Z-direction of a coordinate system. AnX-direction is defined so as to be perpendicular to the longitudinalaxis of the drill tool. Damping portion 200 of the drill pipe is oflength sufficient to reduce the magnetic field due to eddy currents onthe surface of the pipe relative to the induced field produced by eddycurrents in the formation. Transmitter coil 201 induces a magneticmoment within the surrounding formation. The receiver coil assemblycomprises an array of Z-oriented 204 and X-oriented 205 coils havingmagnetic fields oriented so as to detect induced magnetic moments alongorthogonal directions (i.e., M_(x), M_(z)). A series of cuts made in thedamping portion 200 of the drill pipe are typical for suppressing eddycurrents. The drilling tool 200 of FIG. 2 lies horizontally within aformation 230 having resistivity pi and positioned with the longitudinalaxis 210 substantially parallel to a boundary between formation 230 andformation 240 having resistivity ρ₂. The longitudinal axis 210 is at adistance L from boundary 235.

FIGS. 3 a and 3 b show examples of the azimuthal sensitivity of theZ-oriented receiver. FIG. 3 a shows a first layer 301 and second layer302 with the first layer having a resistivity ρ₁ and the second layerhaving a resistivity ρ₂. In the formation used in the example of FIGS. 3a and 3 b, ρ ₁=2 Ω-m and ρ₂=50 Ω-m. Transmitter 305 and receiver coils306 are placed in a second layer so that the line connecting the axialcenters of the transmitter and receiver lies parallel to boundary 310 ata distance L from the boundary between first and second layer. A typicaldistance to the boundary 310 between formations can range from 1 m to 11m. A typical spacing between the transmitter and receiver can vary from0.2 m to 12 m. The line connecting the axial centers of the transmitterand receiver loops lies substantially parallel to interface 310 at adistance L. For the illustrations of FIGS. 3 a and 3 b, transmitter 305and receiver 306 are oriented in the X-direction. In FIG. 3 a, theinduced moment of the X-directed receiver is toward the boundary, and inFIG. 3 b, the induced moment of the X-directed receiver is away from theboundary.

At time t=0, the current flowing through the transmitter coil is shutoff and changes from an initial value I₀ to 0. It should be noted thatthe method described works equally well if the transmitter is turned onand the current in the transmitter increases from a value of zero to avalue of I. In this sense, what is involved is a step discontinuity in acurrent through the transmitter coil. The currents subsequently inducedin the formation (i.e. eddy currents) diffuse outward in all thedirections from the region close to the transmitter coil. These currentsinduce electromagnetic fields in the surrounding formation. Thecomponents of these fields can be measured by induction coils 204 and205 placed along the conductive pipe 200. Measurements are taken whilethe rotating tool 200 moves along the trajectory 210 of the borehole.For a Z-oriented transmitter, where the drill tool lies in ahomogeneous, full-space and horizontal well, the component measured bythe Z-receiver 204 is the only non-zero component. When the drill toollies in a horizontal, layered structure, (such as FIG. 2 and FIGS. 3 aand 3 b) both the Z and X components are non-zero and can be measured.As time increases after the transmitter is turned off, the induced eddycurrents penetrate deeper into the formation and induce currents in themore distant conductive regions of the formation. Consequently, fieldcomponents measured by Z-oriented and X-oriented receivers at earlytimes are indicative of those signals induced in nearby conductiveformations, and field components measured at later times are indicativeof signals induced in more distant conductive formations.

With an X-oriented transmitter, the sensitivity of the X-componentreceivers 205 to the bed boundary 235 varies with time and with thespacing between the transmitter 201 and receiver 205. At early times,the X-receiver is mainly sensitive to the resistivity ρ₁ of the firstformation 230 surrounding the tool. At intermediate times, theX-receiver grows increasingly sensitive to the bed boundary 235, withthe sensitivity to the bed boundary growing from zero to a maximumlevel, then dropping to zero at later times. At late times, the signaldepends on a combination of the resistivities ρ₁ and ρ₂. This isillustrated below with examples shown in FIGS. 4 a, 5 a, 6 a, and 7 a.Typically, at late times, the X-component decays according to$\begin{matrix}\frac{1}{t^{5/2}} & (1)\end{matrix}$

The sensitivity of measurements to the bed boundary also depends on withthe orientation of the receiver. With the same X-directed transmitter,the Z-receiver is sensitive to azimuth. Due to its azimuthal resolutioncapabilities, the Z-component (cross-component) is capable ofdistinguishing between layering of the models of FIG. 3 a and of FIG. 3b, by way of a sign reversal. This feature of the Z-receiver enables avery high sensitivity of the Z-component to the bed boundary locationcompared to the X-component. Hence, cross-component measurements enablea high depth of investigation and an ability to resolve a formation inan azimuthal direction. Specifically, in transient field signals, thesensitivity of the Z-component with respect to a boundary is non-zero atvery early times. This sensitivity reaches a maximum level at earlytimes and then decreases with time. At late times, for R₁/R₂>>1, theZ-component decays as 1/t³. This decay exhibits a higher sensitivity tothe deep formation resistivity than the X-component. Examples arediscussed below with reference to FIGS. 4B, 5B, 6B, and 7B.

Using an array of X and Z receivers such as 204 and 205 respectively inFIG. 2 enables acquiring a set of data that will contain sufficientinformation to find a distance to the boundary and a resistivity of thesurrounding formation. A receiver array typically comprisesapproximately 3 to 5 X-receivers and 3 to 5 Z-receivers. An optimalspacing between the transmitter and X and Z receivers is typically from0 to 10 meters. A plurality of measurements are used to increaserobustness in defining formation parameters. A formation signal istypically measured during the 0.1-100 μsec time interval after thetransmitter 201 is switched off.

The short spacing measurements in the 0.1-100 μsec time interval permitboth the highest resolution to the bed boundary and the largest level ofthe measured signal. Therefore, an advantage of the present invention isthe use of a short transmitter/receiver system as a basic configurationfor MWD geosteering applications. The present invention can detect a bedboundary placed more than 10 m away from the tool. Ideally, a maximumsensitivity to the boundary can be obtained using receivers placed close(i.e. less than 2 m) to the transmitter, and with a signal measuredduring a 0-1 μsec time interval. Practical considerations include thespeed at which the current can be switched off in order to enableaccurate measurements in a time frame of less 0.1 μsec. Also, thedifferences in the orders of magnitude between the sensitivities of theX-component and of the Z-component at short transmitter-receiver spacingis to be considered. Thus an appropriate choice of spacing and timeintervals best enables deep azimuthal measurements.

When an X-transmitter is used, typically the Z-component measurementsare used for azimuthal resolution, while distance to the boundary andresistivity of the formation is obtained from the X-componentmeasurements. Alternatively, a Z-orientation of the transmitter can beused to give a resolution of an oil/water boundary similar to that of anX-oriented transmitter. If a Z-transmitter is used instead of anX-transmitter, typically the X-component measurements are useful forazimuthal resolution, while distance to the boundary and resistivity ofthe formation is obtained from the Z-component measurements.

FIGS. 4 a-b, 5 a-b, 6 a-b, and 7 a-b illustrate the high-resolutioncapabilities of the transient MWD tool of the present invention.Mathematical modeling results are shown using a two-layered formationsuch as shown in FIG. 2. An X-directed transmitter and X- and Z-directedreceivers are used. FIGS. 4 a and 4 b show both X- and Z-components,respectively, obtained at a transmitter-receiver spacing of 0.2 m. Curve401 a represents the response of the tool placed at a distance of 1 mfrom the formation boundary. Curves 403 a, 405 a, 407 a, 409 a, and 411a further represent responses at distances of 3 m, 5 m, 7 m, 9 m and 11m, respectively. Time is plotted in units of seconds along the abscissaand dB_(x)/dt is plotted along the ordinate in units of V/(Am⁴). In FIG.4 b, curve 401 b represents a response of a tool at a distance of 1 mfrom the formation boundary. Curves 403 b, 405 b, 407 b, 409 b, and 411b further represent responses at a distance of 3 m, 5 m, 7 m, 9 m and 11m, respectively. Time is plotted in units of seconds along the abscissaand dB_(z)/dt is plotted along the ordinate in units of V/(Am⁴).

At a transmitter-receiver spacing of 0.2 m, with an X-transmitter, themeasurements of the Z-component in FIG. 4 b have superior resolutioncompared to the X-component in FIG. 4 a. This is seen by the largerseparation of the curves in FIG. 4 b compared to FIG. 4 a. Maximumsensitivity to the bed boundary is typically found at the early times(time less than 5 μsec). In a model having depth-to-boundary less than 5m, practical use of the Z-component is limited, despite increasedresolution, since the signal value of the Z-component is several ordersof magnitude less than the signal value of the X-component, therebyreducing a reliability of measurements in the X-direction. In theinstance of formation models having a depth-to-boundary less than 5 m,the X-component measurement taken in the 0-2 m spacing range during the0.1-100 μsec time interval is sufficient to enable of geo-steering. Inthis case, the sign of the Z-directed component can be used to definewhether the boundary is above or below the tool.

FIGS. 5 a-b, 6 a-b, and 7 a-b present modeling results for atransmitter-receiver spacing of 2 m, 6 m, and 12 m, correspondingly.Increasing the transmitter-receiver spacing increases the magnitude ofthe signal for the Z-component. In addition, increasing the spacingbetween the receiver and the transmitter improves the ratio between X-and Z-directed components of the signal. The choice of spacing isdictated by the operator's decision to resolve and determine parametersof deep formation (deeper than 5 m).

FIGS. 5 a and 5 b shows both X- and Z-components, respectively, obtainedat a transmitter-receiver spacing of 2 m. In FIG. 5A, curve 501 arepresents a response of a tool at a distance of 1 m from the formationboundary. Curves 503 a, 505 a, 507 a, 509 a, and 511 a further representresponses distances of 3 m, 5 m, 7 m, 9 m and 11 m, respectively. Timeis plotted in units of seconds along the abscissa and dB_(x)/dt isplotted along the ordinate in units of V/(Am⁴). In FIG. 5B, Curve 501 brepresents a response of a tool at a distance of 1 m from the formationboundary. Curves 503 b, 505 b, 507 b, 509 b, and 511 b further representresponses at a distance of 3 m, 5 m, 7 m, 9 m and 11 m, respectively.Time is plotted in units of seconds along the abscissa and dB_(z)/dt isplotted along the ordinate in units of V/(Am⁴).

FIGS. 6 a and 6 b shows both X- and Z-components, respectively, obtainedat a transmitter-receiver spacing of 6 m. In FIG. 6 a, curve 601 arepresents a response of a tool at a distance of 1 m from the formationboundary. Curves 603 a, 605 a, 607 a, 609 a, and 611 a further representresponses distances of 3 m, 5 m, 7 m, 9 m and 11 m, respectively. Timeis plotted in units of seconds along the abscissa and dB_(x)/dt isplotted along the ordinate in units of V/(Am⁴). In FIG. 6 b, curve 601 brepresents a response of a tool at a distance of 1 m from the formationboundary. Curves 603 b, 605 b, 607 b, 609 b, and 611 b further representresponses at a distance of 3 m, 5 m, 7 m, 9 m and 11 m, respectively.Time is plotted in units of seconds along the abscissa and dB_(z)/dt isplotted along the ordinate in units of V/(Am⁴).

FIGS. 7 a and 7 b shows both X- and Z-components, respectively, obtainedat a transmitter-receiver spacing of 12 m. In FIG. 7 a, curve 701 arepresents a response of a tool at a distance of 1 m from the formationboundary. Curves 703 a, 705 a, 707 a, 709 a, and 711 a further representresponses at a distance of 3 m, 5 m, 7 m, 9 m and 11 m, respectively.Time is plotted in units of seconds along the abscissa and dB_(x)/dt isplotted along the ordinate in units of V/(Am⁴). In FIG. 7 b, Curve 701 brepresents a response of a tool at a distance of 1 m from the formationboundary. Curves 703 b, 705 b, 707 b, 709 b, and 711 b further representresponses at a distance of 3 m, 5 m, 7 m, 9 m and 11 m, respectively.Time is plotted in units of seconds along the abscissa and dB_(z)/dt isplotted along the ordinate in units of V/(Am⁴).

In another embodiment of the invention, subtracting a system responsefrom a measured signal, can be used to increase a resolution of thetransient system. An embodiment of the apparatus for use in subtractinga system response is shown in FIG. 8 and comprises Z-orientedtransmitter coil 801 and Z-oriented receiver coils 805. The toolschematic and borehole drilling trajectory are also indicated in FIG. 8.

A transmitter coil 801 and a receiver coil assembly are positioned alonga damping portion 800 of drill pipe for suppressing an eddy current. Thelongitudinal axis of the drill tool defines a Z-direction of acoordinate system. An X-direction is defined so as to be perpendicularto the longitudinal axis of the drill tool. Damping portion 800 of thedrill pipe is of length sufficient to reduce a flow of eddy currents.Transmitter coil 801 induces a magnetic field substantially along theZ-direction. The receiver coil assembly comprises an array of Z-orientedcoils 805. The drilling tool of FIG. 2 lies horizontally disposed withina formation 830 having resistivity ρ₁ and positioned with longitudinalaxis 810 substantially parallel to a boundary 835 between formation 830and formation 840 having resistivity ρ₂. The longitudinal axis 810 is ata distance L from boundary 835.

FIG. 9 shows a cross-section of the tool of FIG. 8. Conductive pipe 900is surrounded on its outer diameter by a non-conducting material 910.The non-conductive material 910 can be magnetic, for example. Anencapsulated Z-directed transmitter 920 is disposed along the outercircumference of the non-conductive material 910. The ferrite coating910 reduces the contribution of the conductive pipe into the measuredtransient signal while boosting a signal contribution from theformation. Since ferrite coating increases an inductance of the system,this configuration enables a short length of the ferrite pipe.

Typical behavior of the transient signal can be studied using acylindrical two-layered formation that simulates water/oil contact 835.The system is placed into the first layer 830 having resistivity ρ₁=50Ω-m. Resistivity of the second layer is ρ₂=2 Ω-m. For FIGS. 10-15, thesecond layer 840 is located at different distances ranging from 4 m to10 m from the tool. The spacing between the transmitter and receiver isvaried between 0.5 m and 8 m.

FIGS. 10 a-b, 11 a-b, and 12 a-b show two types of signals obtained viamathematical modeling at different transmitter-receiver spacings. Thesignals of FIGS. 10 a, 11 a, and 12 a are measured by the receiver coil805 after the current in the transmitter 801 is switched off. Thesignals of FIGS. 10 b, 11 b, and 12 b are derived from the signals ofFIGS. 10 a, 11 a, and 12 a by subtracting the system response(calibration signal) measured in the absence of formation. The signalsof FIGS. 10 b, 11 b, and 12 b (differential signals) have a superiorresolution with respect to determining a position of the water/oilboundary.

In FIGS. 10-12, the length of the ferrite section is 1 m and the 0.5 mtransmitter/receiver pair is centered with respect to it. Theresistivity of the pipe is 0.714×10⁻⁶ Ω-m. The resistivity of the firstlayer is 50 Ω-m, and the resistivity of the second pipe is 2 Ω-m, andμ=400. In FIGS. 13-15, the length of the ferrite section is increased to1.5 m.

In FIG. 10 a, signals are obtained at a depth-to-boundary of 4 m, 6 m, 8m, and 10 m using a transmitter-receiver spacing of 0.5 m. As shown inFIG. 10 a, the signals at these distances are early indistinguishablefrom one another. These curves are collectively labeled as 1000. Anobtained signal due to a pipe outside a formation is shown in curve1020. Differential signals obtained by subtracting pipe signal 1020 areshown in FIG. 10B. Curves for a depth-to-boundary spacing of 4 m, 6 m, 8m, and 10 m are shown as 1004, 1006, 1008, and 1010 correspondingly.

Similarly, in FIG. 11 a, signals are obtained at a depth-to-boundary of4 m, 6 m, 8 m, and 10 m using a transmitter-receiver spacing of 2.0 m.The signals of FIG. 11 a can be slightly distinguished from one another.Curves obtained at depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 mare labeled 1103, 1105, 1107, and 1109, correspondingly. Differentialsignals obtained by subtracting pipe signal 1120 are shown in FIG. 11 b.Curves for a depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m areshown as 1104, 1106, 1108, and 1110 correspondingly.

In FIG. 12 a, signals are obtained at a depth-to-boundary of 4 m, 6 m, 8m, and 10 m using a transmitter-receiver spacing of 8.0 m. Curvesobtained at depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m arelabeled 1203, 1205, 1207, and 1209, correspondingly. Differentialsignals obtained by subtracting pipe signal 1220 are shown in FIG. 12 b.Curves for a depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m areshown as 1204, 1206, 1208, and 1210 correspondingly.

In FIG. 12 a, where the receiver placed 8 m away from the transmitter,there is a capability of resolving 8 m and 10 m water/oil boundarydistances. But even at this transmitter receiver spacing, the signallevel measured by this receiver is in the range of 0.1-0.01 μV. For MWDapplication, higher resolution and smaller transmitter/receiver spacingis desirable.

To increase a resolution of the transient system, differentialmeasurements are made where the system response is subtracting for theoriginal measured signals. For instance, subtracting the pipe response1020 from those curves simultaneously labeled as 1000 in FIG. 10 ayields curves 1004, 1006, 1008, and 1010 of FIG. 10 b. The differentialtransient signal has improved resolution with respect to the oil/waterboundary and the signal level at a transmitter-receiver spacing of 0.5 mis in the range of microvolts, even for the far-located 10 m oil/waterboundary. As in any other differential measurements, the challenge inthe transient differential measurements is to provide sufficientaccuracy in the signals involved into the operation of subtraction. Asshown in FIG. 10 b, and FIG. 11 b, the differential curves are 10-100times less than the calibration curve (in case of 10 m distance to theboundary). In case of 100 times ratio between calibration (or original)curve and differential curve, the last is hard to synthesize withsufficient accuracy.

Increasing the length of the ferrite, for example, to 1.5 m, improvesthe ratio of the differential curve to the calibration curve. Thecorresponding modeling results for a ferrite pipe of length 1.5 m arepresented in FIGS. 13 a, 14 a, and 15 a, along with the differentialcurves presented in FIGS. 13 b, 14 b and 15 b. FIG. 13 b shows that thedifferential signal is well-resolved with respect to oil/water distance,has high level (˜10 μV) and only 15 times less than calibration signal(10 m distance to the boundary, 10 μsec time moment). This signal can beboth reliably derived and accurately interpreted.

In FIG. 13 a, signals are obtained at a depth-to-boundary of 4 m, 6 m, 8m, and 10 m using a transmitter-receiver spacing of 0.5 m. Curvesobtained at depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m arelabeled 1303, 1305, 1307, and 1309, correspondingly. Differentialsignals obtained by subtracting pipe signal 1320 are shown in FIG. 13B.Curves for a depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m areshown as 1304, 1306, 1308, and 1310 correspondingly.

In FIG. 14 a, signals are obtained at a depth-to-boundary of 4 m, 6 m, 8m, and 10 m using a transmitter-receiver spacing of 2.0 m. Curvesobtained at depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m arelabeled 1403, 1405, 1407, and 1409, correspondingly. Differentialsignals obtained by subtracting pipe signal 1820 are shown in FIG. 14 b.Curves for a depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m areshown as 1404, 1406, 1408, and 1410 correspondingly.

In FIG. 15 a, signals are obtained at a depth-to-boundary of 4 m, 6 m, 8m, and 10 m using a transmitter-receiver spacing of 8.0 m. Curvesobtained at depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m arelabeled 1503, 1505, 1507, and 1509 correspondingly. Differential signalsobtained by subtracting pipe signal 1520 are shown in FIG. 15 b. Curvesfor a depth-to-boundary spacing of 4 m, 6 m, 8 m, and 10 m are shown as1504, 1506, 1508, and 1510 correspondingly.

It should be pointed out that the present invention has been describedabove with reference to X- and Z-component transmitters and receivers.This is not intended to be a limitation since it is well known in theart to perform a rotation of coordinates whereby orthogonal measurementscan be obtained from measurements made with receivers having coils thatare simply inclined to each other.

A particular application of either of the embodiments of the inventiondescribed above is in reservoir navigation. An example of the use ofresistivity is given in U.S. Pat. RE35386 to Wu et al, having the sameassignee as the present application and the contents of which are fullyincorporated herein by reference. Disclosed in Wu is a method fordetecting and sensing boundaries between strata in a formation duringdirectional drilling so that the drilling operation can be adjusted tomaintain the drillstring within a selected stratum is presented. Themethod comprises the initial drilling of an offset well from whichresistivity of the formation with depth is determined. This resistivityinformation is then modeled to provide a modeled log indicative of theresponse of a resistivity tool within a selected stratum in asubstantially horizontal direction. A directional (e.g., horizontal)well is thereafter drilled wherein resistivity is logged in real timeand compared to that of the modeled horizontal resistivity to determinethe location of the drill string and thereby the borehole in thesubstantially horizontal stratum. From this, the direction of drillingcan be corrected or adjusted so that the borehole is maintained withinthe desired stratum. The resistivity measurements made in Wu are madewith a conventional electromagnetic (EM) propagation resistivityinstrument. The measurements made with a propagation EM tool lackdirectional information. Another example of reservoir navigation usingmulticomponent measurements is described in copending U.S. patentapplication Ser. No. 10/373,365 of Merchant et al., having the sameassignee as the present invention and the contents of which are fullyincorporated herein by reference. The principles described in Wu orMechant can be used with transient measurements (as described above) formaintaining the drillstring at a desired distance from an interface,such as a gas-oil contact or an oil-water contact.

The method and apparatus of the present invention has been describedabove with reference to a MWD embodiment. This is not to be construed asa limitation as the invention can also be practiced with the apparatusconveyed on a wireline.

While the foregoing disclosure is directed to the preferred embodimentsof the invention, various modifications will be apparent to thoseskilled in the art. It is intended that all such variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

1. A method of using an electromagnetic instrument in a borehole in anearth formation comprising: (a) changing a current through a transmitteron said instrument and inducing currents in said earth formation, saidtransmitter having a first axial direction; (b) receiving first andsecond temporal signals resulting from said induced currents in at leasttwo receivers, a first one of said at least two receivers having anaxial direction that is substantially parallel to said first axialdirection, and a second one of said at least two receivers having anaxial direction inclined to said first axial direction; and (c)determining from said first and second temporal signals a distance to aninterface in said earth formation.
 2. The method of claim 1 furthercomprising determining a direction to said interface.
 3. The method ofclaim 1 wherein said changing of said current through said transmittercomprises turning off said current through said transmitter.
 4. Themethod of claim 1 wherein said changing of said current through saidtransmitter comprises turning on a current through said transmitter. 5.The method of claim 1 further comprising: (i) changing a current in anadditional transmitter on said instrument, said additional transmitterhaving an axis inclined to said first axial direction, and inducingadditional currents in said earth formation, (ii) receiving third andfourth temporal signals resulting from said additional induced currentsin said first and second receivers, and (iii) using said third andfourth temporal signals in said determining of said distance.
 6. Themethod of claim 1 wherein said first axial direction is substantiallyparallel to said axis of said instrument.
 7. The method of claim 5wherein said second one of said at least two eceivers has an axissubstantially orthogonal to said first axis.
 8. The method of claim 1wherein said electromagnetic instrument is conveyed on a bottomholeassembly (BHA) into said borehole, the method further comprising usingsaid determined distance for controlling a drilling direction of saidBHA.
 9. The method of claim 1 wherein said interface comprises a bedboundary.
 10. The method of claim 1 wherein said interface comprises afluid interface selected from: (i) a gas-oil interface, (ii) anoil-water interface, and (iii) a gas-water interface.
 11. A method ofusing an electromagnetic instrument in a borehole in an earth formationcomprising: (a) changing a current through a transmitter on saidinstrument and inducing currents in said earth formation; (b) receivinga temporal signal resulting from said induced current in at at least onereceiver on said instrument, said received temporal signal includingeffects of a conductive body of said instrument; (c) determining fromsaid reference signal and said temporal signal a distance to aninterface in sad earth formation, said determination being substantiallyunaffected by said conductive body.
 12. The method of claim 11 furthercomprising determining a direction to said interface.
 13. The method ofclaim 11 wherein said step of determining further comprises subtractingsaid reference signal from said temporal signal.
 14. The method of claim11 wherein said changing of said current through said transmittercomprises turning off said current through said transmitter.
 15. Themethod of claim 11 wherein said changing of said current through saidtransmitter comprises turning on a current through said transmitter. 16.The method of claim 11 wherein said transmitter has an axial directionsubstantially parallel to an axis of said instrument.
 17. The method ofclaim 11 further comprising obtaining said reference signal by measuringa temporal signal in a substantially homogenous medium.
 18. The methodof claim 11 wherein said electromagnetic instrument is conveyed on abottomhole assembly (BHA) into said borehole, the method furthercomprising using said determined distance for controlling a drillingdirection of said BHA.
 19. The method of claim 11 wherein said interfacecomprises a bed boundary.
 20. The method of claim 11 wherein saidinterface comprises a fluid interface selected from: (i) a gas-oilinterface, (ii) an oil-water interface, and (iii) a gas-water interface.21. An apparatus for use in a borehole in an earth formation comprising:(a) an instrument including a transmitter for inducing currents in saidearth formation, said transmitter having a first axial direction; (b) atleast two receivers on said instrument for receiving first and secondtemporal signals resulting from said induced currents, a first one ofsaid at least two receivers having an axial direction that issubstantially parallel to said first axial direction, and a second oneof said at least two receivers having an axial direction inclined tosaid first axial direction; and (c) a processor for determining fromsaid first and second temporal signals a distance to an interface insaid earth formation.
 22. The apparatus of claim 21 wherein saidprocessor further determines a direction to said interface.
 23. Theapparatus of claim 21 further comprising: (i) an additional transmitteron said instrument, said additional transmitter having an axis inclinedto said fist axial direction, said additional transmitter inducingadditional currents in said earth formation, wherein said first andsecond receivers receive third and fourth temporal signals resultingfrom said additional induced currents in said first and secondreceivers, and wherein said processor further uses said third and fourthtemporal signals in said determining of said distance.
 24. The apparatusof claim 21 wherein said first axial direction is substantially parallelto said axis of said instrument.
 25. The apparatus of claim 23 whereinsaid second one of said at least two receivers has an axis substantiallyorthogonal to said first axis.
 26. The apparatus of claim 21 furthercomprising a bottomhole assembly (BHA) for conveying saidelectromagnetic instrument into said borehole, the processor furtherusing said determined distance for controlling a drilling direction ofsaid BHA.
 27. The apparatus of claim 21 wherein said interface comprisesa bed boundary.
 28. The apparatus of claim 21 wherein said interfacecomprises a fluid interface selected from; (i) a gas-oil interface, (ii)an oil-water interface, and (iii) a gas-water interface.
 29. Anapparatus for use in a borehole in an earth formation comprising: (a) aninstrument having a conductive body and including a transmitter forinducing currents in said earth formation; (b) at least one receiver onsaid instrument for receiving a temporal signal resulting from saidinduced current, said temporal signal being affected by said conductivebody, (c) a processor for determining from a reference signal and saidtemporal signal a distance to an interface in said earth formation, saiddetermination being substantially unaffected by said conductive body.30. The apparatus of claim 29 wherein said processor further determinesa direction to said interface.
 31. The apparatus of claim 29 whereinsaid processor subtracts said reference signal from said temporalsignal.
 32. The apparatus of claim 29 wherein said transmitter has anaxial direction substantially parallel to an axis of said instrument.33. The apparatus of claim 29 wherein said reference signal is obtainedby measuring a temporal signal in a substantially homogenous medium. 34.The apparatus of claim 29 further comprising a bottomhole assembly (BHA)for conveying said electromagnetic instrument into said borehole, theprocessor further uses said determined distance for controlling adrilling direction of said BHA.
 35. The apparatus of claim 29 whereinsaid interface comprises a bed boundary.
 36. The apparatus of claim 29wherein said interface comprises a fluid interface selected from: (i) agas-oil interface, (ii) an oil-water interface, and (iii) a gas-waterinterface.
 37. The apparatus of claim 29 wherein said instrumentcomprises a conductive tubular member, and said transmitter is separatedfrom said tabular member by a non-conductive material.
 38. The apparatusof claim 37 wherein said non-conductive material comprises a ferrite.